**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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FORM 10-Q

**x**                              QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Act of1934 for the quarterly period ended March 31, 2005

**or**

**o**                                 TransitionReport Pursuant to Section 13 or 15(d) of the Securities Exchange Act of1934 for the transition period from                    to                    

**Commission File Number: 0-6910**

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TELOFFSHORE TRUST

(Exact Name of Registrantas Specified in its Charter)

| **Texas**                                                                                    | **76-6004064**                       |
|----------------------------------------------------------------------------------------------|--------------------------------------|
| (State of  Incorporation,  or Organization)                                                  | I.R.S. Employer  Identification No.) |
| **JPMorgan Chase Bank, N.A.  Worldwide Security Services  700 Lavaca Street  Austin, Texas** | **78701**                            |
| (Address of  Principal  Executive Offices)                                                   | (Zip Code)                           |

 

Registrant’s TelephoneNumber, Including Area Code: **(512) 479-2562**

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports) and (2) hasbeen subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant is anaccelerated filer (as defined in Rule 12b-2 of the SecuritiesExchange Act of 1934). Yes o  No x

Indicate the number of shares outstanding of each ofthe registrant’s classes of common stock, as of the latest practicable date.

Asof May 13, 2005—4,751,510 Units of Beneficial Interest in TEL OffshoreTrust.

 

 

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**NOTEREGARDING FORWARD-LOOKING STATEMENTS**

This Form 10-Q includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-Q are forward-looking statements. Although theWorking Interest Owners (as defined herein) have advised the Trust that theybelieve that the expectations reflected in the forward-looking statementscontained herein are reasonable, no assurance can be given that suchexpectations will prove to have been correct. Important factors that couldcause actual results to differ materially from expectations (“CautionaryStatements”) are disclosed in this Form 10-Q, including, withoutlimitation, in conjunction with the forward-looking statements includedin this Form 10-Q. A summary of certain principal risks andCautionary Statements is also included in the Trust’s most recent Form 10-Kunder “Business—Principal Trust Risk Factors.” All subsequent written and oralforward-looking statements attributable to the Trust or persons acting onits behalf are expressly qualified in their entirety by the CautionaryStatements.

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**PART I—FINANCIALINFORMATION**

**Item 1. FinancialStatements.**

**TEL OFFSHORE TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**
| ** **                                                                                                                                 | ** ** | **    March 31,      2005** | ** ** | **  December 31,   2004** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| **Assets**                                                                                                                                 |       |                                                                     |       |                                          |       |   |   |   |   |
| Cash and cash  equivalents                                                                                                                 |       |                                                                     | $          | 1,726,355                                     |       |   |   | $ | 3,811,210 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,180,203 and $28,177,602,  respectively |       |                                                                     | 87,452     |                                          |       |   | 90,053 |   |   |
| Total assets                                                                                                                               |       |                                                                     | $          | 1,813,807                                     |       |   |   | $ | 3,901,263 |   |   |
| **Liabilities and Trust Corpus**                                                                                                           |       |                                                                     |       |                                          |       |   |   |   |   |
| Distribution  payable to Unit holders                                                                                                      |       |                                                                     | $          | 316,435                                       |       |   |   | $ | 2,470,196 |   |   |
| Reserve for  future Trust expenses                                                                                                         |       |                                                                     | 1,409,920  |                                          |       |   | 1,341,014 |   |   |
| Commitments and  contingencies                                                                                                             |       |                                                                     |       |                                          |       |   |   |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                          |       |                                                                     | 87,452     |                                          |       |   | 90,053 |   |   |
| Total liabilities and  Trust corpus                                                                                                        |       |                                                                     | $          | 1,813,807                                     |       |   |   | $ | 3,901,263 |   |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**
| ** **                                                | ** ** | **Three Months Ended  March 31,**                                                         | ** ** |
|-----------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                                | ** ** | **        2005        ** | ** ** | **        2004        ** | ** ** |
| Royalty income                                            |       |                                                                                                     | $          | 526,972 |   |   |   | $ | 0 |   |   |
| Interest income                                           |       |                                                                                                     | 2,821      |   |   |   | 1,768 |   |   |
|                                                      |       |                                                                                                     | 529,793    |   |   |   | 1,768 |   |   |
| (Increase)/Decrease in reserve  for future Trust expenses |       |                                                                                                     | (68,906    | ) |   |   | 142,798 |   |   |
| General and  administrative expenses                      |       |                                                                                                     | (144,452   | ) |   |   | (144,566 | ) |   |
| Distributable  income                                     |       |                                                                                                     | $          | 316,435 |   |   |   | $ | 0 |   |   |
| Distributions per Unit  (4,751,510 Units)                 |       |                                                                                                     | $          | .066597 |   |   |   | $ | 0.000000 |   |   |

 

The accompanying notes are an integral part of thesefinancial statements.

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**STATEMENTS OFCHANGES IN TRUST CORPUS(Unaudited)**
| ** **                                       | ** ** | **Three Months Ended  March 31,** | ** ** |
|--------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                       | ** ** | **2005**                                         | ** ** | **2004** | ** ** |
| Trust corpus,  beginning of period               |       | $                                                | 90,053     |   | $ | 154,619 |   |
| Distributable  income                            |       | 316,435                                          |       | 0 |   |
| Distribution  payable to Unit holders            |       | (316,435                                         | )          | 0 |   |
| Amortization of  net overriding royalty interest |       | (2,601                                           | )          | (13,332 | ) |
| Trust corpus, end of  period                     |       | $                                                | 87,452     |   | $ | 141,287 |   |

 

The accompanying notes arean integral part of these financial statements.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS**

**(Unaudited)**

**Note 1 — TrustOrganization**

Tenneco Offshore Company, Inc.(“Tenneco Offshore”) created the TEL Offshore Trust (“Trust”) effective January 1,1983, pursuant to the Plan of Dissolution (“Plan”) approved by Tenneco Offshore’sstockholders on December 22, 1982. In accordance with the Plan, the TELOffshore Trust Partnership (“Partnership”) was formed in which the Trust owns a99.99% interest and Tenneco Oil Company (“Tenneco”) initially owned a .01%interest. In general, the Plan was effected by transferring an overridingroyalty interest (“Royalty”) equivalent to a 25% net profits interest in theoil and gas properties (the “Royalty Properties”) of TennecoExploration, Ltd. (“Exploration I”) located offshore Louisiana to thePartnership and issuing certificates evidencing units of beneficial interest inthe Trust (“Units”) in liquidation and cancellation of Tenneco Offshore’scommon stock.

On October 31, 1986,Exploration I was dissolved and the oil and gas properties of Exploration Iwere distributed to Tenneco subject to the Royalty. Tenneco, who was thenserving as the Managing General Partner of the Partnership, assumed theobligations of Exploration I, including its obligations under the instrumentconveying the Royalty to the Partnership (the “Conveyance”). The dissolution ofExploration I had no impact on future cash distributions to holders of units ofbeneficial interest.

On November 18, 1988,Chevron U.S.A., Inc. (“Chevron”) acquired most of the Gulf of Mexicooffshore oil and gas properties of Tenneco, including all of the RoyaltyProperties. As a result of the acquisition, Chevron replaced Tenneco as theWorking Interest Owner and Managing General Partner of the Partnership. Chevronalso assumed Tenneco’s obligations under the Conveyance.

On October 30, 1992,PennzEnergy Company (“PennzEnergy”) (which merged with and into Devon EnergyProduction Company L.P. effective January 1, 2000) acquired certain oiland gas producing properties from Chevron, including four of the RoyaltyProperties. The four Royalty Properties acquired by PennzEnergy were EastCameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As aresult of such acquisition, PennzEnergy replaced Chevron as the WorkingInterest Owner of such properties on October 30, 1992. PennzEnergy alsoassumed Chevron’s obligations under the Conveyance with respect to theseproperties.

On December 1, 1994,Texaco Exploration and Production Inc. (“TEPI”) acquired two of theRoyalty Properties from Chevron. The Royalty Properties acquired by Texaco wereWest Cameron 643 and East Cameron 371/381. As a result of such acquisitions,TEPI replaced Chevron as the Working Interest Owner of such properties on December 1,1994. TEPI also assumed Chevron’s obligations under the Conveyance with respectto these properties.

On October 1, 1995, SONAT Exploration Company (“SONAT”)acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1,1995, Amoco Production Company (“Amoco”) acquired the Eugene Island 367property from PennzEnergy. As a result of such acquisitions, SONAT and Amocoreplaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued)**

**(Unaudited)**

**Note 1 —Trust Organization (Continued)**

Eugene Island367 properties, respectively, on October 1, 1995 and also assumedPennzEnergy’s obligations under the Conveyance with respect to theseproperties.

Effective January 1,1998, Energy Resource Technology, Inc. (“ERT”) acquired the East Cameron354 property from SONAT. As a result of such acquisition, ERT replaced SONAT asthe Working Interest Owner of the East Cameron 354 property effective January 1,1998, and also assumed SONAT’s obligations under the Conveyance with respect tosuch property. In October 1998, Amerada Hess Corporation (“Amerada”)acquired the East Cameron 354 property from ERT effective January 1, 1998.As a result of such acquisition, Amerada replaced ERT as the Working InterestOwner of the East Cameron 354 property effective January 1, 1998, and alsoassumed ERT’s obligations under the Conveyance with respect to this property.

Effective January 1,2000 PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon EnergyProduction Company L.P. (“Devon”). As a result of such merger, Devon replacedPennzEnergy as the Working Interest Owner of Eugene Island 348 and EugeneIsland 208 properties effective January 1, 2000, and also assumedPennzEnergy’s obligations under the Conveyance with respect to theseproperties.

On October 9, 2001, awholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged(the “Merger”) with and into Texaco Inc., a Delaware corporation (“Texaco”),pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000.As a result of the Merger, Texaco Inc. became a wholly owned subsidiary ofChevron Corporation, and Chevron Corporation changed its name to “ChevronTexacoCorporation” in connection with the Merger. Effective May 9, 2005, ChevronTexacoCorporation changed its name to Chevron Corporation. Accordingly, theproperties referred to herein by Chevron and Texaco are each now controlled bysubsidiaries of Chevron Corporation.

On May 1, 2002, TEPIassigned all of its interests in West Cameron 643 and East Cameron 371/381 toChevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, netprofits interest will be calculated for the collective Royalty Properties ownedby Chevron after this date.

On June 6, 2003 AnadarkoPetroleum Corporation (“Anadarko”) acquired, among other interests, a 25% WorkingInterest in the East Cameron 354 field subject to a 25% Net Profit Interestproperty from Amerada effective April 1, 2003. As a result of thistransaction, Anadarko replaced Amerada as the Working Interest Owner of EastCameron 354 effective July 1, 2003 and also assumed Amerada’s obligationsunder the conveyance with respect to said property.

Effective October 1, 2004,Apache acquired Anadarko’s interest in East Cameron 354 and assumed Anadarko’sobligations under the conveyance with respect to this property.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued)**

**(Unaudited)**

**Note 1 — Trust Organization (Continued)**

All of the RoyaltyProperties continue to be subject to the Royalty, and it is anticipated thatthe Trust and the Partnership, in general, will continue to operate as if theabove-described sales of the Royalty Properties had not occurred.

Unless the context in which such terms are usedindicates otherwise, in these Notes to Financial Statements the terms “WorkingInterest Owner” and “Working Interest Owners” generally refer to the owner orowners of the Royalty Properties (Tenneco Exploration, Ltd. through October 31,1986; Tenneco for periods from October 31, 1986 until November 18,1988; Chevron with respect to all Royalty Properties for periods from November 18,1988 until October 30, 1992, and with respect to all Royalty Propertiesexcept East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island208 for periods from October 30, 1992 until December 1, 1994, andwith respect to the same properties except West Cameron 643 thereafter;PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, EugeneIsland 367 and Eugene/Devon Island 208 for periods from October 30, 1992until October 1, 1995, and with respect to Eugene Island 348 and EugeneIsland 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron371/381 for periods beginning on or after December 1, 1994 until May 1,2002; SONAT with respect to East Cameron 354 for periods beginning on or after October 1,1995; and Amoco with respect to Eugene Island 367 for periods beginning on orafter October 1, 1995; Amerada with respect to East Cameron 354 forperiods beginning on or after January 1, 1998; Chevron with respect toWest Cameron 643 and East Cameron 371/381 on and after May 1, 2002; andAnadarko with respect to East Cameron 354 on and after July 1, 2003 untilOctober 1, 2004; and Apache with respect to East Cameron 354 after October 1,2004).

**Note 2 — Basisof Accounting**

Theaccompanying unaudited financial information has been prepared by JPMorganChase Bank, N.A. (formerly known as The Chase Manhattan Bank and thesuccessor by merger to the original name of the Corporate Trust, Texas CommerceBank National Association) (“Corporate Trustee”) in accordance with theinstructions to Form 10-Q and does not include all of theinformation required by accounting principles generally accepted in the UnitedStates of America for complete financial statements, although the CorporateTrustee and the individual trustees (collectively, the “Trustees”) believe thatthe disclosures are adequate to make the information presented not misleading.The information furnished reflects all adjustments which are, in the opinion ofthe Trustees, necessary for a fair presentation of the results for the interimperiods presented. The financial information should be read in conjunction withthe financial statements and notes thereto included in the Trust’s AnnualReport on Form 10-K for the year ended December 31, 2004.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued)**

**(Unaudited)**

**Note 2 —Basis of Accounting (Continued)**

The financial statementsof the Trust are prepared on the following basis:

(a)           Royaltyincome is recorded when received, including the effect of overtaken orundertaken positions and negative or positive adjustments, by the CorporateTrustee on the last business day of each calendar quarter; and

(b)          Trustgeneral and administrative expenses are recorded when paid, except for the cashreserved for future general and administrative expenses, as discussed inNote 7.

This manner of reportingincome and expenses is considered to be the most meaningful because thequarterly distributions to Unit holders are based on net cash receipts receivedfrom the Working Interest Owners. The financial statements of the Trust differfrom financial statements prepared in accordance with generally acceptedaccounting principles, because, under such principles, Royalty income and Trustgeneral and administrative expenses for a quarter would be recognized on anaccrual basis. In addition, amortization of the net overriding royaltyinterest, which is calculated on a units-of-production basis, is chargeddirectly to Trust corpus since such amount does not affect distributableincome.

Cash and cash equivalentsinclude all highly liquid, short-term investments with original maturities ofthree months or less.

The decrease in reservefor future Trust expenses includes both decreases of amounts deemed necessaryby the Trustees and related distributions, as well as amounts paid from thereserve during periods when the Trust has insufficient income to pay Trustexpenses.

The Trust reviews the netoverriding royalty interest in oil and gas properties for possible impairmentwhenever events or circumstances indicate the carrying amount of the asset maynot be recoverable. If there is an indication of impairment, the Trust preparesan estimate of future cash flows (undiscounted and without interest charges)expected to result from the use of the asset and its eventual disposition. Ifthese cash flows are less than the carrying amount of the asset, an impairmentloss is recognized to write down the asset to its estimated fair value. Preparationof estimated expected future cash flows is inherently subjective and is basedon the Corporate Trustee’s best estimate of assumptions concerning expectedfuture conditions. There were no write downs taken in the periods presented.

The preparation offinancial statements requires the Trustees to make use of estimates andassumptions that affect amounts reported in the financial statements as well ascertain discounts. Actual results could differ from those estimates.

The Trustees, includingthe Corporate Trustee, have no authority over, have not evaluated and make nostatement concerning, the internal control over financial reporting of theworking interest owners.

The amount of cash distributions by the Trust isdependent on, among other things, the sales prices for oil and gas producedfrom the Royalty Properties and the quantities of oil and gas sold. It shouldbe noted that substantial uncertainties exist with regard to future oil and gasprices, which are subject to 

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued)**

**(Unaudited)**

**Note 2 —Basis of Accounting (Continued)**

materialfluctuations due to changes in production levels and pricing and other actionstaken by major petroleum producing nations, as well as the regional supply anddemand for gas, weather, industrial growth, conservation measures, competitionand other variables. The Trust does not enter into any hedging transactions onfuture production.

**Note 3— Net Overriding Royalty Interest**

The Royalty entitles theTrust to its share (99.99%) of 25% of the Net Proceeds attributable to the RoyaltyProperties. The Conveyance, dated January 1, 1983, provides that theWorking Interest Owners will calculate, for each period of three monthscommencing the first day of February, May, August and November, an amountequal to 25% of the Net Proceeds from their oil and gas properties for theperiod. Generally, “Net Proceeds” means the amounts received by the WorkingInterest Owners from the sale of minerals from the Royalty Properties lessoperating and capital costs incurred, management fees and expensereimbursements owing to the Managing General Partner of the Partnership,applicable taxes other than income taxes, and a special cost reserve. TheSpecial Cost Escrow account (See Note 6) is established for the futurecosts to be incurred to plug and abandon wells, dismantle and remove platforms,pipelines and other production facilities, and for the estimated amount offuture capital expenditures on the Royalty Properties. Net Proceeds do notinclude amounts received by the Working Interest Owners as advance gaspayments, “take-or-pay” payments or similar payments unless and until suchpayments are extinguished or repaid through the future delivery of gas.

**Note 4— Distributions to Unit Holders**

In accordance with theprovisions of the Trust Agreement, generally all Net Proceeds received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. Such distributions are referredto as “distributable income.” The amounts distributed are determined on aquarterly basis and are payable to Unit holders of record as of the lastbusiness day of each calendar quarter. However, cash distributions are made inJanuary, April, July and October and include interest earned from thequarterly record date to the date of distribution.

During the quarter ended March 31,2004, a Working Interest Owner made certain negative adjustments to previouslyreported Net Proceeds (See Note 5). Due to these negative adjustments aswell as to significant capital expenditure incurred on the Royalty Properties,there was no Royalty income for the quarter. As a result of these negativeadjustments, the deficit balance to the Trust at March 31, 2004 increasedby $2,727,521 resulting in a loss carryforward of $3,307,628. In the secondquarter of 2004, Net Proceeds were offset by the loss carryforward of$3,307,628 with a resulting loss carryforward balance of $0 at June 30, 2004.No distributable income was available to unit holders in the second quarter of2004 since the Trust recoups expenses being paid from the reserve for Trustexpense that the Trustees have established for anticipated future expenses. Duringthe quarter ended September 30, 2004, the Trust resumed distributions as thereserve for trust expenses had been funded.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued)**

**(Unaudited)**

**Note 5 — Negative Adjustments**

During the quarter ended March 31, 2004, aWorking Interest Owner informed the Trust that it had made errors in priorperiods which resulted in prior periods Net Proceeds being overstated. ThisWorking Interest Owner, Chevron, which is also the Managing General Partner,has advised the Trust that these errors consisted of:

·        EugeneIsland 339—a $6,953,982 gross revenue adjustment to reverse revenues previouslycredited to the Trust for interest in wells that the Trust does not hold aninterest, a $98,797 gross operating expense adjustment and a $573,382adjustment to increase previous capital expenditures

·        ShipShoal 182/183—a $1,336,287 gross adjustment to reverse revenues previouslycredited to the Trust primarily for double-counted production and a$1,855,976 adjustment to correct previously recorded adjustments to capitalexpenditures

·        SouthTimbalier 36/37 (Royalty Properties associated with subsidiaries of ChevronCorporation)—a $495,425 gross adjustment to reverse the effects of clericalerrors.

The Trust recorded theadjustments during the first quarter of 2004, which resulted in a loss carryforwardof $3,307,628 as of March 31, 2004. In the second quarter of 2004, Net Proceedswere sufficient to fully offset the loss carryforward of $3,307,628, resultingin no further loss carryforward.

**Note 6 — Special Cost Escrow Account**

The Special Cost Escrow is an account of the WorkingInterest Owners, and it is described herein for informational purposes only.The Conveyance provides for the reserve of funds for estimated future “SpecialCosts” of plugging and abandoning wells, dismantling platforms and other costsof abandoning the Royalty Properties, as well as for the estimated amount offuture drilling projects and other capital expenditures on the Royalty Properties.As provided in the Conveyance, the amount of funds to be reserved is determinedbased on certain factors, including estimates of aggregate future productioncosts, aggregate future Special Costs, aggregate future net revenues and actualcurrent net profits interest. Deposits into this account reduce currentdistributions and are placed in an escrow account and invested in short-termcertificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts. Special Cost Escrow funds will generally be utilized to pay SpecialCosts to the extent there are not adequate current net profits interest to paysuch costs. Special Costs that have been paid are no longer included in theSpecial Cost Escrow calculation. Deposits to the Special Cost Escrow accountwill generally be made when the balance in the Special Cost Escrow account isless than 125% of estimated future Special Costs and there is a Net RevenuesShortfall (a calculation of the excess of estimated future costs over estimatedfuture net revenues pursuant to a formula contained in the Conveyance). Whenthere is not a Net Revenues Shortfall, amounts in the Special Cost Escrowaccount will generally be released, to the extent that Special Costs have beenincurred. Amounts in the Special Cost 

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued)**

**(Unaudited)**

**Note 6 —Special Cost Escrow Account (Continued)**

Escrow account generallywill also be released when the balance in such account exceeds 125% ofestimated future Special Costs. In the first quarter of 2005, there was a net depositof funds to the Special Cost Escrow account of $1,940,994. In the first quarterof 2004, there was a net release of funds from the Special Cost Escrow account.The Trust’s share of the funds released was $853,016. As of March 31, 2005,$7,320,222 remained in the Special Cost Escrow account.

Chevron, in its capacityas Managing General Partner, has advised the Trust that additional deposits tothe Special Cost Escrow account may be required in future periods in connectionwith other production costs, other abandonment costs, other capitalexpenditures and changes in the estimates and factors described above. Suchdeposits could result in a significant reduction in Royalty income in theperiods in which such deposits are made, including the possibility that noRoyalty income would be received in such periods.

**Note 7— Reserve For Future Trust Expenses**

The Trust made adetermination in 1998 to maintain a cash reserve equal to three times theaverage expenses of the Trust during each of the past three years to providefor future administrative expenses in connection with the winding up of theTrust. The reserve amount at March 31, 2005 was $1,409,920. The reserve amount atMarch 31, 2004 was $1,760,592. During the first quarter of 2004, the Trust used$142,798 from the Trust’s cash reserve account to pay the Trust’s general andadministrative expenses, when insufficient Royalty income was received by theTrust, reducing the reserve amount held by the Trust to $1,221,613 as of March 31,2004.

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**Item2. Management’s Discussion and Analysis of Financial Condition and Results ofOperations.**

**Critical Accounting Policies**

The financialstatements of the Trust are prepared on the following basis:

(a)           Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter; and

(b)          Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses.

This manner ofreporting income and expenses is considered to be the most meaningful becausethe quarterly distributions to Unit holders are based on net cash receiptsreceived from the Working Interest Owners. The financial statements of theTrust differ from financial statements prepared in accordance with generallyaccepted accounting principles, because, under such principles, Royalty incomeand Trust general and administrative expenses for a quarter would be recognizedon an accrual basis. In addition, amortization of the net overriding royaltyinterest, calculated on a units-of-production basis, is charged directly toTrust corpus since such amount does not affect distributable income.

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**Financial Review**

**Three Months Ended March 31,2005 and 2004**

Distributions to the Unitholders for the three months ended March 31, 2005 amounted to $316,435 or$.066597 per Unit as compared to no distributions for the same period in 2004.The increase in distributable income for the first quarter of 2005 wasprimarily as a result of negative adjustments to Net Proceeds and significantcapital expenditures that reduced Royalty income in the first quarter of 2004.

There were no distributions for the three months endedMarch 31, 2004. The Trust was in a deficit position with Working InterestOwners as a result of negative adjustments to Net Proceeds relating to priorperiods. The negative adjustments made refer to downward adjustments torevenues and production by Chevron based on an improper credit to the Trust ofrevenues and production on Eugene Island 339. This improper credit related toproduction credited from wells in which the Trust has no interest from as earlyas June 2002 through October 2003.

Crude oil and condensate revenues increased $10,501,175to $8,370,945 in the first quarter of 2005 as compared to $(2,130,230) in thefirst quarter of 2004, due to a 300% increase in crude oil and condensatevolume to 187,778 barrels in the first quarter of 2005 from (93,080) barrels inthe first quarter of 2004. The negative revenues and volumes for the firstquarter of 2004 are due to negative adjustments, as a result of the impropercredits of production and revenues by Chevron, totaling 295,224 barrelsrecorded by the Trust. The average price of crude oil and condensate increased from$30.19 per barrel in the first quarter of 2004 to $44.58 per barrel in the firstquarter of 2005.

Gas revenues increased $2,041,797, or 141%, to $3,493,955in the first quarter of 2005 from $1,452,158 in the first quarter of 2004, dueto a increase in gas volumes of 109% to 493,708 Mcf in the first quarter of 2005from 236,155 Mcf in the first quarter of 2004, and by a $0.93 or 15% increasein the average price received for natural gas to $7.08 per Mcf in the firstquarter of 2005 from $6.15 per Mcf in the first quarter of 2004. Gas productsrevenue increased $475,723, to $466,717 in the first quarter of 2005 from $(9,006)in the first quarter of 2004 due primarily to a increase in production volume of593,473 gallons to 568,544 from (24,929) gallons. The negative revenues andvolumes for the first quarter of 2004 are due to negative adjustments, as aresult of the improper credits of production and revenues by Chevron.

The Trust’s share of capital expenditures decreased $12,606,485,from $13,879,199 in the first quarter of 2004 to $1,272,714 in the firstquarter of 2005. The decrease in capital expenditures for the first quarter of2005 related primarily to drilling of the new I-4 well and some residualcosts from completion of I-2 and I-3 wells on the Ship Shoal182/183 property in the first quarter of 2004, compared to capital expendituresfor the same period in 2005 which were related to the purchase of a compressoron the Ship Shoal 182/183 property and some residual costs from wellcompletions on Eugene Island 339. The Trust recorded an adjustment of$2,026,684 in the first quarter of 2004 relating primarily to charges incurredin the fourth quarter of 2003. Adjustments to capital expenditures are based onmiscalculations and duplication of downward adjustments allocations on ShipShoal 182/183 during the third and fourth quarters of 2003. Thesemiscalculations and duplications are reflected in the amounts provided.

The Trust did not have undistributed net income in thefirst quarter of 2005. For the three months ending March 31, 2004, the negativeadjustments discussed above relating to production in previous 

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periods exceeded proceedsfrom oil and gas sales for the first quarter of 2004. The loss carryforward at March 31,2004 of $3,307,628 were deducted from future gross proceeds on the RoyaltyProperties.

In the first quarter of 2005, there was a net depositof funds into the Special Cost Escrow account. The Trust’s share of the funds depositedwas $1,940,994. The deposit was primarily a result of additional futureestimated abandonment costs and future capital expenditures. As of March 31,2005, $7,320,222 remained in the Special Cost Escrow account. The Special CostEscrow is set aside for estimated abandonment costs and future capitalexpenditures as provided for in the Conveyance. For additional informationrelating to the Special Cost Escrow see “Special Cost Escrow” account below.

In the first quarter of2004, there was a net refund of funds into the Special Cost Escrow account. TheTrust’s share of the funds released was $853,016.

**Reserve for Future Trust Expenses**

In accordance with theprovisions of the Trust Agreement, generally all Royalty income received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. In the first quarter of 1998,the Trust determined that the Trust’s cash reserve was sufficient at that timeto provide for future administrative expenses in connection with the winding upof the Trust. The Trust determined that a cash reserve equal to three times theaverage expenses of the Trust during each of the past three years wassufficient at this time to provide for future administrative expenses inconnection with the winding up of the Trust. The reserve amount for 2004 was $1,760,592.The reserve amount for 2005 was $1,409,920.

**Other**

The amount of cashdistributed by the Trust is dependent on, among other things, the sales pricesand quantities of oil and gas produced from the Royalty Properties. It shouldbe noted that substantial uncertainties exist with regard to future oil and gasprices, which are subject to material fluctuations due to changes in productionlevels and pricing and other actions taken by major petroleum producingnations, as well as the regional supply and demand for oil and gas, weather,industrial growth, conservation measures, competition and other variables.

**Operational Review**

**Three Months Ended March 31, 2005 and 2004**

*Volumes and dollaramounts discussed below represent amounts recorded by the Working InterestOwners unless otherwise specified.*

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During the quarterended March 31, 2004, a Working Interest Owner informed the Trust that ithad made errors in prior periods which resulted in prior periods Net Proceedsbeing overstated. This Working Interest Owner, Chevron, which is also theManaging General Partner, has advised the Trust that these errors consisted of:

·        EugeneIsland 339—a $6,953,982 gross revenue adjustment to reverse revenues previouslycredited to the Trust for an interest in wells that the Trust does not hold aninterest, a $98,797 gross operating expense adjustment and a $573,382adjustment to increase previous capital expenditures

·        ShipShoal 182/183—a $1,336,287 gross adjustment to reverse revenues previouslycredited to the Trust primarily for double-counted production and a$1,855,976 adjustment to correct previously recorded adjustments to capitalexpenditures

·        SouthTimbalier 36/37 (Royalty Properties associated with subsidiaries of ChevronCorporation)—a $495,425 gross adjustment to reverse the effects of clericalerrors.

The gross adjustments, before the Special Cost Escrowaccount adjustment, was $10,911,175 or a $2,727,521 increase in the losses tobe carried forward and netted against future Net Proceeds earned by the Truston Royalty Properties operated by this Working Interest Owner.

Ship Shoal 182/183 crude oil revenues increased from $2,407,576in the first quarter of 2004 to $4,251,634 in the first quarter of 2005,primarily due to an increase in net crude oil production from 79,415 barrels inthe first quarter of 2004, which included a negative retroactive adjustment of44,214 barrels relating to the fourth quarter of 2003 discussed above, to91,356 barrels in the first quarter of 2005. The average crude oil price increasedfrom $30.32 per barrel in the first quarter of 2004 to $46.54 per barrel forthe same period in 2005. Gas revenues increased from $1,055,621 in the firstquarter of 2004 to $1,627,972 in the first quarter of 2005 due to an increasein the average natural gas sales price from $5.77 per Mcf in the first quarterof 2004 to $7.07 per Mcf for the same period in 2005. Gas production alsoincreased from 182,867 Mcf in the first quarter of 2004 to 230,289 Mcf in thefirst quarter of 2005. The increase in gas volume primarily resulted from theaddition of the E-11 well in late October 2004. Capital expenditures decreasedfrom $7,767,450 in the first quarter of 2004 to $657,885 in the first quarterof 2005 primarily due to $6.3 million of capital expenditures made tocompete the F-3 drilling project in the first quarter of 2004. Operatingexpenses decreased from $960,089 in the first quarter of 2004 to $309,907 forthe same period in 2005.

Eugene Island 339 net crude oil revenues increasedfrom $(4,212,676) in the first quarter of 2004 to $3,995,299 for the sameperiod in 2005 due to an increase in volumes to 93,732 barrels from (162,170)barrels in the first quarter of 2004, which included a negative retroactiveadjustment of 236,650 barrels relating to the period of January through October 2003for improper credits of production and revenues discussed above. In addition,the average crude oil price increased from $25.98 per barrel in the firstquarter of 2004 to $42.62 per barrel in the first quarter of 2005. Gas revenuesincreased from $244,807 in the first quarter 2004 to $1,519,141 in the firstquarter of 2005 primarily due to a increase in natural gas volumes from 29,024Mcf in the first quarter of 2004, which gave effect to a negative retroactiveadjustment of 90,976 Mcf for improper credits of production and revenuesdiscussed above, to 211,558 Mcf in the first quarter of 2005. Capitalexpenditures decreased from $6,127,098 in the first quarter of 2004 to $589,057in the first quarter of 2005 due to various capital projects that werecompleted in the first quarter of 2004, including the C-20 and C-21drilling projects that cost approximately $1.5 and $3.3 million, 

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respectively, and upgradesto the C platform facilities that cost approximately $517,000. Operatingexpenses decreased from $587,353 in the first quarter of 2004 to $337,108 inthe first quarter of 2005.

West Cameron 643 gas revenues increased from $80,081in the first quarter of 2004 to $296,606 in the first quarter of 2005. This isdue to an increase in gas volumes from 17,833 Mcf in the first quarter of 2004to 44,773 Mcf for the same period in 2005. Operating expenses increased from $69,151in the first quarter of 2004 to $154,926 for the same period in 2005, andcapital expenditures increased from $515 in the first quarter of 2004 to $1,034for the same period in 2005.

East Cameron 371/381 crudeoil revenues decreased from $8,849 in the first quarter of 2004 to $1,005 inthe first quarter of 2005 primarily due to the decrease in crude oil productionfrom 286 barrels in the first quarter of 2004 to 22 barrels for the same periodin 2005. The decrease was partially offset by an increase in the average crudeoil price from $30.96 per barrel in the first quarter of 2004 to $45.69 perbarrel in the first quarter of 2005. Gas revenues decreased from $21,247 in thefirst quarter of 2004 to $10,770 in the first quarter of 2005. This is due to adecrease in gas volumes from 4,561 Mcf in the first quarter of 2004 to 1,476Mcf for the same period in 2005. The decrease in volumes was partially offsetby an increase in the average price received for natural gas from $4.66 per Mcfin the first quarter of 2004 to $7.30 per Mcf in the first quarter of 2005.Capital expenditures were $41 in the first quarter of 2004 and were $1 in the firstquarter of 2005. Operating expenses increased from $5,963 in the first quarterof 2004 to $12,012 in the first quarter of 2005.

**FutureNet Revenues and Termination of the Trust**

Based on a reserve studyprovided to the Trust by DeGolyer and MacNaughton, independent petroleumengineers, as of October 31, 2004 future net revenues attributable to theTrust’s royalty interests were estimated at $30.2 million. Estimates ofproved oil and gas resterver attributable to the Partnership’s royalty interestare based on existing economic and operating conditions in effect at October 31in order to correspond to with distributions to the Trust. Such reserve studyalso indicates that approximately 75% of the future net revenues from theRoyalty Properties are expected to be received by the Trust during the nextthree years. In addition, because the Trust will terminate in the eventestimated future net revenues fall below $2 million, it would be possiblefor the Trust to terminate even though some or all of the Royalty Propertiescontinued to have remaining productive lives. Upon termination of the Trust,the Trustees will sell for cash all of the assets held in the Trust estate andmake a final distribution to Unit holders of any funds remaining after allTrust liabilities have been satisfied. The estimates of future net revenuesdiscussed above are subject to large variances from year to year and should notbe construed as exact. There are numerous uncertainties present in estimatingfuture net revenues for the Royalty Properties. The estimate may vary dependingon changes in market prices for crude oil and natural gas, the recoverablereserves, annual production and costs assumed by DeGolyer and MacNaughton. Inaddition, future economic and operating conditions as well as results of futuredrilling plans may cause significant changes in such estimate. The discussionset forth above is qualified in its entirety by reference to the Trust’s 2004Annual Report on Form 10-K. The Form 10-K is availableupon request from the Corporate Trustee.

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**Special Cost Escrow Account**

The Conveyance provides for reserving funds forestimated future “Special Costs” of plugging and abandoning wells, dismantlingplatforms and other costs of abandoning the Royalty Properties, as well as forthe estimated amount of future drilling projects and other capital expenditureson the Royalty Properties. As provided in the Conveyance, the amount of fundsto be reserved is determined based on factors including estimates of aggregatefuture production costs, aggregate future Special Costs, aggregate future netrevenues and actual current net profits interest. Deposits into this accountreduce current distributions and are placed in an escrow account and invested inshort-term certificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts. Special Cost Escrow funds will generally be utilized to pay SpecialCosts to the extent there are not adequate current net profits interest to paysuch costs. Special Costs that have been paid are no longer included in theSpecial Cost Escrow calculation. Deposits to the Special Cost Escrow accountwill generally be made when the balance in the Special Cost Escrow account isless than 125% of estimated future Special Costs and there is a Net RevenuesShortfall (a calculation of the excess of estimated future costs over estimatedfuture net revenues pursuant to a formula contained in the Conveyance). Whenthere is not a Net Revenues Shortfall, amounts in the Special Cost Escrowaccount will generally be released, to the extent that Special Costs have beenincurred. Amounts in the Special Cost Escrow account generally will also bereleased when the balance in such account exceeds 125% of estimated futureSpecial Costs. In the first quarter of 2005, there was a net deposit of funds tothe Special Cost Escrow account of $1,940,994. The deposit was primarily aresult of additional future estimated abandonment costs and future capitalexpenditures.

In the first quarter of 2004, there was a net releaseof funds from the Special Cost Escrow account. The Trust’s share of the funds releasedwas $853,016. As of March 31, 2005, $7,320,222 remained in the SpecialCost Escrow account.

Chevron, in its capacity as Managing General Partner,has advised the Trust that additional deposits to the Special Cost Escrowaccount may be required in future periods in connection with other productioncosts, other abandonment costs, other capital expenditures and changes in theestimates and factors described above. Such deposits, if made, could result ina significant reduction in Royalty income in the periods in which such depositsare made, including the possibility that no Royalty income would be received insuch periods.

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**Overviewof Production, Prices and Royalty Income**

The following scheduleprovides a summary of the volumes and weighted average prices for crude oil andcondensate and natural gas recorded by the Working Interest Owners for theRoyalty Properties, as well as the Working Interest Owners’ calculations of theNet Proceeds and the royalties paid to the Trust during the periods indicated.Net Proceeds due to the Trust are calculated for each three-month periodcommencing on the first day of February, May, August and November.
| ** **                                                       | ** ** | **Royalty Properties  Three Months Ended  March 31,**(4) | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2005**                                                                     | ** ** | **2004** | ** ** |
| Crude oil and  condensate (bbls)(1)                              |       | 187,778                                                                      |       | (93,080 | ) |
| Natural gas and  gas products (Mcf)(2)                           |       | 574,929                                                                      |       | 232,594 |   |
| Crude oil and  condensate average price, per bbl(1)              |       | $                                                                            | 44.58      |   | $ | 22.89 |   |
| Natural gas  average price, per Mcf (excluding gas products) (2) |       | $                                                                            | 7.08       |   | $ | 6.15 |   |
| Crude oil and  condensate revenues(1)                            |       | $                                                                            | 8,370,945  |   | $ | (2,130,230 | ) |
| Natural gas and  gas products revenues(2)                        |       | 3,960,672                                                                    |       | 1,443,152 |   |
| Production  expenses(3)                                          |       | (1,259,653                                                                   | )          | (2,084,693 | ) |
| Capital  expenditures(3)                                         |       | (1,272,714                                                                   | )          | (13,879,199 | ) |
| Undistributed net  loss (income)(5)                              |       | 0                                                                            |       | (16,650,970 | ) |
| Refund of  (provision for) escrowed special costs                |       | (7,691,152                                                                   | )          | 3,412,064 |   |
| **Net  Proceeds**                                                |       | 2,108,098                                                                    |       | 0 |   |
| Royalty interest                                                 |       | x25                                                                          | %          | x25 | % |
| Partnership share                                                |       | 527,025                                                                      |       | 0 |   |
| Trust interest                                                   |       | x99.99                                                                       | %          | x99.99 | % |
| Trust share                                                      |       | $                                                                            | 526,972    |   | $ | 0 |   |

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(1)          Includes negative volumeadjustments of 295,224 bbls for the three months ended March 31, 2004.Exclusive of these adjustments volumes would have been 202,143 bbls. Excludingthe impact of these adjustments crude oil and condensate average price per bblwould have been $30.19. Excluding the impact of these adjustments crude oil andcondensate revenues would have been $6,102,141.

(2)          Includes negative volumeadjustments of 106,334 Mcf for the three months ended March 31, 2004.Exclusive of these adjustments volumes would have been 338,928 Mcf. Excludingthe impact of these adjustments natural gas average price per Mcf would havebeen $5.86 and natural gas and condensate revenue would have been $1,996,475.

(3)          Includes negativeadjustments of $2,125,481 for the three months ended March 31, 2004.Excluding the impact of these adjustments production expense would have been$1,985,896 and capital expenditures would have been $11,852,514.

(4)          The amounts for thethree months ended March 31, 2005 and 2004 represent actual production forthe periods November 2004 through January 2005, and November 2003through January 2004, respectively.

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(5)          Undistributednet loss represents negative Net Proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive Net Proceeds earned by the related Working InterestOwner(s). Undistributed net income represents positive Net Proceeds, generated duringthe respective period that was applied to an existing loss carryforward. As of March 31,2004, the loss carryforward was $3,307,628.

**Item3. Quantitative and Qualitative Disclosure About Market Risk**

No material changes haveoccurred since our Annual Report on Form 10-K for the year-ended December 31,2004. Reference is also made to Note 2 of the Notes to FinancialStatements included in Item 1 of this Form 10-Q.

**Item 4. Controls and Procedures.**

(a)   *Evaluationof disclosure controls and procedures.*

The Corporate Trustee maintains disclosure controlsand procedures designed to ensure that information required to be disclosed bythe Trust in the reports that it files or submits under the Exchange Act of1934, as amended, is recorded, processed, summarized and reported within thetime periods specified in the SEC’s rules and regulations. Disclosure controlsand procedures include controls and procedures designed to ensure thatinformation required to be disclosed by the Trust is accumulated andcommunicated by Chevron, as the managing general partner of the Partnership,and the working interest owners to JPMorgan Chase Bank, N.A., as Corporate Trusteeof the Trust, and its employees who participate in the preparation of theTrust’s periodic reports as appropriate to allow timely decisions regardingrequired disclosure.

As of the end of the period covered by this report,the Corporate Trustee carried out an evaluation of the Trust’s disclosurecontrols and procedures. Mike Ulrich, as Trust Officer of the CorporateTrustee, has concluded that the disclosure controls and procedures of the Trustare effective.

Due to thecontractual arrangements of (i) the Trust Agreement, (ii) thePartnership Agreement and (iii) the rights of the Partnership under theConveyance regarding information furnished by the working interest owners,there are certain limits on the scope of the Trust’s disclosure controls andprocedures that are not subject to change or modification by the CorporateTrustee. The contractual limitations and reliance that may affect informationcontained in this report include:

·        TheWorking Interest Owners alone control (i) historical operating data,including production volumes, marketing of products, operating and capitalexpenditures, environmental and other liabilities, the effects of regulatorychanges and the number of producing wells and acreage, (ii) plans forfuture operating and capital expenditures, (iii) geological data relatingto reserves, as well as other information used by the independent reserveengineer to prepare the reserve report containing projected production,operating expenses and capital expenses and (iv) information relating to projectedproduction. While the Corporate Trustee requests material information for usein periodic reports as part of its disclosure controls and procedures, neitherthe Trustees nor the managing general partner of the Partnership (to the extentthe managing general partner is not also the Working Interest Owner) controlthis information, and they rely entirely on the Working 

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Interest Owners to provideaccurate and timely information when requested for use in the Trust’s reports.

·        TheTrustees, including the Corporate Trustee, rely on information provided by themanaging general partner of the Partnership that is collected by the managinggeneral partner from the Working Interest Owners. While the Trustees mayrequest information through the managing general partner, the Conveyancetogether with the Partnership Agreement gives only the managing general partnerof the Partnership, as the Royalty Owner, the actual authority and discretionto request and receive financial information regarding the Royalty Propertiesfrom the Working Interest Owners. While the Corporate Trustee requests materialinformation for use in periodic reports as part of its disclosure controls andprocedures, the Trustees, including the Corporate Trustee, generally do nothave any direct contact with Working Interest Owners, other than the managinggeneral partner, and rely on the managing general partner of the Partnership torequest and obtain information deemed material by the Trustees.

·        Underthe terms of the Trust Agreement, the Trustees, including the CorporateTrustee, are entitled to, and in fact do rely, upon certain experts in goodfaith, including (i) the independent reserve engineer with respect to theannual reserve report, which includes projected production, operating expensesand capital expenses, and (ii) the independent auditors with whom theyhave contracted with respect to audits of financial data provided by themanaging general partner and working interest owners. Other than contractingindependent auditors and reviewing the managing general partner’s statements ona quarterly basis, the Trustees make no independent or direct verification ofthis financial information. The Conveyance also restricts access to and thereview of confidential reserve data provided by working interest owners to theindependent reserve engineer.

The Trustees do not intend to expand theirresponsibilities beyond those permitted or required by the Trust Agreement andthose required under applicable law.

Information regarding operations provided by theWorking Interest Owners, including Chevron, has been subject to errors and adjustments,some of which have been significant. These include errors and adjustments thatare reflected in this report and other historical reports. Accordingly, whilethe Trustees make diligent inquiries and request changes to internal controlsof the Working Interest Owners when errors are identified, the Trustees cannotassure Unit holders that other errors or adjustments by Working InterestOwners, whether historical or future, will not affect future Royalty income anddistributions by the Trust.

*Changes in Internal Control OverFinancial Reporting.  *To the knowledge of the CorporateTrustee, during the three months ended March 31, 2005, there has been nochange in the Corporate Trustee’s internal control over financial reportingthat has materially affected, or is reasonably likely to materially affect, theCorporate Trustee’s internal control over financial reporting relating to theTrust. The Corporate Trustee notes for purposes of clarification that it has noauthority over, has not evaluated and makes no statement concerning, theinternal control over financial reporting of the Working Interest Owners or themanaging general partner of the Partnership.

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**PART II—OTHER INFORMATION**

**Item6. Exhibits**

(Asteriskindicates exhibit previously filed with the Securities and Exchange Commissionand incorporated herein by reference.)
|        | ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                      | ** ** | **SEC File or  Registration  Number** | ** ** | **Exhibit  Number** |
|--------|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|---------------------|
| 4(a)*  |       | —     | Trust Agreement dated as of January 1, 1983,  among Tenneco Offshore Company, Inc., Texas Commerce Bank National  Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus  and F. Arnold Daum, as individual trustees (Exhibit 4(a) to  Form 10-K for the year ended December 31, 1992 of TEL  Offshore Trust) |       | 0-6910                                |       | 4(a)                |
| 4(b)*  |       | —     | Agreement of General Partnership of TEL Offshore  Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust,  dated January 1, 1983 (Exhibit 4(b) to Form 10-K  for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                 |       | 0-6910                                |       | 4(b)                |
| 4(c)*  |       | —     | Conveyance of Overriding Royalty Interests from  Exploration I to the Partnership (Exhibit 4(c) to Form 10-K  for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                       |       | 0-6910                                |       | 4(c)                |
| 4(d)*  |       | —     | Amendments to TEL Offshore Trust Agreement, dated  December 7, 1984 (Exhibit 4(d) to Form 10-K for  year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                                |       | 0-6910                                |       | 4(d)                |
| 4(e)*  |       | —     | Amendment to the Agreement of General Partnership of  TEL Offshore Trust Partnership, effective Offshore Trust)                                                                                                                                                                                                                                                 |       | 0-6910                                |       | 4(e)                |
| 10(a)* |       | —     | Purchase Agreement, dated as of December 7, 1984  by and between Tenneco Oil Company and Tenneco Offshore II Company  (Exhibit 10(a) to Form 10-K for year ended  December 31, 1992, of TEL Offshore Trust)                                                                                                                            |       | 0-6910                                |       | 10(a)               |
| 10(b)* |       | —     | Consent Agreement, dated November 16, 1988,  between TEL Offshore Trust and Tenneco Oil Company  (Exhibit 10(b) to Form 10-K for year ended  December 31, 1988 of TEL Offshore Trust)                                                                                                                                                  |       | 0-6910                                |       | 10(b)               |
| 10(c)* |       | —     | Assignment and Assumption Agreement, dated  November 17, 1988, between Tenneco Oil Company and TOC-Gulf of  Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended  December 31, 1988 of TEL Offshore Trust)                                                                                                                           |       | 0-6910                                |       | 10(c)               |
| 10(d)* |       | —     | Gas Purchase and Sales Agreement Effective  September 1, 1993 between Tennessee Gas Pipeline Company and Chevron  U.S.A. Production Company (Exhibit 10(d) to Form 10-K  for year ended December 31, 1993 of TEL Offshore Trust)                                                                                                       |       | 0-6910                                |       | 10(d)               |
| 31     |       | —     | Certification furnished pursuant to Section 302  of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                         |       |                                  |       |                |
| 32     |       | —     | Certification furnished pursuant to Section 906  of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                         |       |                                  |       |                |

 

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized.
|            | TEL OFFSHORE TRUST |
|------------|--------------------|
|       | By:                |   | JPMorgan Chase Bank, N. A.  Corporate Trustee |
|       | By:                | ** ** | /s/  MIKE ULRICH |
| ** ** | ** **         | ** ** | **Mike Ulrich  Vice President** |

 

Date: May 13, 2005

The Registrant, TEL Offshore Trust, has no principalexecutive officer, principal financial officer, board of directors or personsperforming similar functions. Accordingly, no additional signatures areavailable and none have been provided.

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